Precipitated Particles and Wellbore Fluids and Methods Relating Thereto

ABSTRACT

Precipitated mineral particles may provide for wellbore fluids with tailorable properties and capabilities. Such wellbore fluids may be included as a portion of a wellbore drilling assembly that includes a pump in fluid communication with a wellbore via a feed pipe; and a wellbore fluid disposed in at least one selected from the group consisting of the pump, the feed pipe, the wellbore, and any combination thereof, wherein the wellbore fluid has a density of about 7 ppg to about 50 ppg and comprises a base fluid and a plurality of precipitated particles having a shape selected from the group consisting of ovular, substantially ovular, discus, platelet, flake, toroidal, dendritic, acicular, spiked with a substantially spherical or ovular shape, spiked with a discus or platelet shape, rod-like, fibrous, polygonal, faceted, star-shaped, and any hybrid thereof.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation-in-part of and claims priorityto U.S. patent application Ser. No. 13/752,697 filed on Jan. 29, 2013,entitled “Precipitated Particles and Wellbore Fluids and MethodsRelating Thereto,” the entire disclosure of which is incorporated hereinby reference.

BACKGROUND

The present invention relates to precipitated particles and wellborefluids and methods relating thereto.

In the exploration and recovery of hydrocarbons from subterraneanformations, a variety of wellbore operations are performed, e.g.,drilling operations, cementing operations, and stimulation operations.One physical property of the wellbore fluids used in conjunction withthese wellbore operations is density. For example during drillingoperations, the density of a wellbore fluid must be carefully controlledso as to exert sufficient pressure to stabilize the walls of thewellbore, e.g., to prevent blowouts, while simultaneously not exertingexcess pressure that can cause damage to the surrounding subterraneanformation. In another example, the density of spacer fluids andcementing operations must be carefully balanced so as to minimize orprevent mixing of other wellbore fluids on either side of the spacerfluid (e.g., a drilling fluid and a cementing fluid).

Changing the density of wellbore fluids is often achieved with the useof particles (often referred to in the art as weighting agents). Thecharacteristics of weighting agent particles (e.g., specific gravity andparticle size distribution) effect not only the density of the wellborefluid, but also other wellbore fluid properties, like sag and viscosity.The ability to tailor the properties of the weighting agent to achievedesired wellbore fluid characteristics may allow for reduced cost byminimizing the need for other additives because the tailored weightingagent can achieve the desired wellbore fluid characteristics. However,the grinding process used to produce weighting agents provides littletailorability in terms of particle characteristics.

The characteristics of the weighting agent particles (e.g., particleshape and particle size distribution) is primarily determined by thegrinding procedure and the composition of the bulk mineral including anycontaminants. In some instances, sieves can be used to remove at leastsome of the larger or smaller particle sizes from the ground material.However, this provides limited ability to tailor the average particlesize and particle size distribution of the weighting agent particles.Moreover, the grind process offers no ability to tailor the shape andmorphology of the weighting agent particles. Accordingly, methods thatallow for the production of weighting agents with tailoredcharacteristics and the methods that employ the resultant wellborefluids would be of value to one in the art.

SUMMARY OF THE INVENTION

The present invention relates to precipitated particles and wellborefluids and methods relating thereto.

One embodiment of the present invention provides for a wellbore drillingassembly that includes a pump in fluid communication with a wellbore viaa feed pipe; and a wellbore fluid disposed in at least one selected fromthe group consisting of the pump, the feed pipe, the wellbore, and anycombination thereof, wherein the wellbore fluid has a density of about 7ppg to about 50 ppg and comprises a base fluid and a plurality ofprecipitated particles having a shape selected from the group consistingof ovular, substantially ovular, discus, platelet, flake, toroidal,dendritic, acicular, spiked with a substantially spherical or ovularshape, spiked with a discus or platelet shape, rod-like, fibrous,polygonal, faceted, star-shaped, and any hybrid thereof.

Another embodiment of the present invention provides for a wellboredrilling assembly that includes a pump in fluid communication with awellbore via a feed pipe; a drill string with drill bit attached to thedistal end of the drill string; and a wellbore fluid in contact with thedrill bit, wherein the wellbore fluid has a density of about 7 ppg toabout 50 ppg and comprises a base fluid and a plurality of precipitatedparticles having a shape selected from the group consisting of ovular,substantially ovular, discus, platelet, flake, toroidal, dendritic,acicular, spiked with a substantially spherical or ovular shape, spikedwith a discus or platelet shape, rod-like, fibrous, polygonal, faceted,star-shaped, and any hybrid thereof.

Yet another embodiment of the present invention provides for a wellboredrilling assembly that includes a pump capable of introducing a fluidinto a wellbore via a feed pipe; a fluid processing unit capable ofreceiving the fluid from a wellbore via an interconnecting flow line;and a wellbore fluid disposed in at least one selected from the groupconsisting of the pump, the feed pipe, the wellbore, the interconnectingflow line, the fluid processing unit, and any combination thereof,wherein the wellbore fluid has a density of about 7 ppg to about 50 ppgand comprises a base fluid and a plurality of precipitated particleshaving a shape selected from the group consisting of ovular,substantially ovular, discus, platelet, flake, toroidal, dendritic,acicular, spiked with a substantially spherical or ovular shape, spikedwith a discus or platelet shape, rod-like, fibrous, polygonal, faceted,star-shaped, and any hybrid thereof.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent invention, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, as willoccur to those skilled in the art and having the benefit of thisdisclosure.

FIGS. 1A-B illustrate examples of theoretical multi-modal diameterdistributions for particles.

FIG. 2 illustrates an exemplary wellbore drilling assembly for use inconjunction with the mineral particles, related fluids, and relatedmethods described herein.

DETAILED DESCRIPTION

The present invention relates to precipitated particles and wellborefluids and methods relating thereto.

The present invention provides for, in some embodiments, precipitatedparticles that can be used in subterranean applications as uniqueweighting agents. Precipitated particle characteristics like shape andparticle size distribution may, in some embodiments, be tailored duringprecipitation synthesis, for example, through pH and/or temperature.Further, precipitation as a synthesis method may allow for unique shapesand narrow particle size distributions that can be exploited so as toachieve desired properties and capabilities in the correspondingwellbore fluids (e.g., density, viscosity, and sag control). Forexample, discus or platelet shaped precipitated particles may increasethe viscosity of a wellbore fluid and settle in the wellbore fluid at aslower rate, thereby yielding a viscosified fluid with less sag.

The ability to tailor the properties and capabilities of wellbore fluidsmay advantageously allow for the a reduction in other, potentiallyexpensive and less environmentally-desirable, additives because thecharacteristics of the precipitated particles provide for the desiredproperties and capabilities of the wellbore fluid.

Further, the purity of the precipitated particles may be utilized tobring mined or ground weighting agents into an acceptable specification.For example, some grades of mined barite contain high levels of sand andother particles. Precipitated particles described herein may be combinedwith such ground barite to decrease the overall abrasiveness andincrease specific gravity of the weighting agent additive. In otherexamples, ground minerals that are mined in some areas of the world mayhave higher levels of heavy metals like mercury or cadmium. Theinclusion of the higher purity precipitated particles may dilute thecontaminants to acceptable levels.

It should be noted that when “about” is used herein at the beginning ofa numerical list, “about” modifies each number of the numerical list. Itshould be noted that in some numerical listings of ranges, some lowerlimits listed may be greater than some upper limits listed. One skilledin the art will recognize that the selected subset will require theselection of an upper limit in excess of the selected lower limit.

It should be noted that unless otherwise specified, the term“precipitated particles” encompasses single types of precipitatedparticles and combinations of more than one type of particle, includingcombinations of precipitated particles with non-precipitated particles.Distinctions between types of precipitated particles may, in someembodiments, be defined by at least one of composition, shape, mediandiameter, aspect ratio, diameter distribution, presence or absence ofcoating, coating composition, and the like, and any combination thereof.

In some embodiments, the precipitated particles described herein may beformed by precipitation methods. The precipitation methods mayadvantageously yield precipitated particles that have desiredcharacteristics (e.g., size, shape, diameter distribution, mediandiameter, and the like).

Some embodiments of the present invention may involve precipitatingparticles from two or more salts in aqueous solutions so as to yield theprecipitated particles described herein (or precursors to precipitatedparticles described herein, e.g., particles that can be further calcinedto yield precipitated particles described herein). For example, someembodiments of the present invention may involve precipitating manganesecarbonate from manganese (II) salts in aqueous solutions with alkalimetal carbonates so as to yield the precipitated manganese carbonateparticles. Examples of other salts that may be used in producingprecipitated particles may include salts (e.g., fluorides, chlorides,bromides, iodides, acetates, formates, citrates, sulfates, carbonates,hydroxides, phosphates, silicates, molybdates, tungstates, vanadates,titanates, chromates, and the like) of barium, bismuth, chromium,cobalt, copper, gold, iron, lead, nickel, strontium, tin, zinc,manganese, tungsten, aluminum, silver, cerium, magnesium, zirconium,titanium, calcium, antimony, lead, and the like, and any combinationthereof.

In some embodiments, the concentration of salts used in the formation ofprecipitated particles may range from a lower limit of about 1 mM, 10mM, or 50 mM to an upper limit of about 5 M, 1 M, or 100 mM, and whereinthe concentration may range from any lower limit to any upper limit andencompasses any subset therebetween.

In some embodiments, the precipitated particles described herein thatare formed by precipitation methods may comprise at least one of AgI,AgCl, AgBr, AgCuS, AgS, Ag₂S, Al₂O₃, AsSb, AuTe₂, BaCO₃, BaSO₄, BaCrO₄,BaO, BeO, BiOCl, (BiO)₂CO₃, BiO₃, Bi₂S₃, Bi₂O₃, CaO, CaF₂, CaWO₄, CaCO₃,(Ca,Mg)CO₃, CdS, CdTe, Ce₂O₃, CoAsS, Cr₂O₃, CuO, Cu₂O, CuS, Cu₂S, CuS₂,Cu₉S₅, CuFeS₂, Cu₅FeS₄, CuS.Co₂S₃, Fe²⁺Al₂O₄, Fe₂SiO₄, FeWO₄, FeAs₂,FeAsS, FeS, FeS₂, FeCO₃, Fe₂O₃, α-Fe₂O₃, α-FeO(OH), Fe₃O₃, FeTiO₃, HgS,Hg₂Cl₂, MgO, MnCO₃, Mn₂S, MnWO₄, MnO, MnO₂, Mn₂O₃, Mn₃O₃, Mn₂O₇,MnO(OH), CaMoO₄, MoS₂, MOO₂, MOO₃, NbO₄, NiO, NiAs₂, NiAs, NiAsS, NiS,PbTe, PbSO₄, PbCrO₄, PbWO₄, PbCO₃, (PbCl)₂CO₃, Pb²⁺ ₂Pb⁴⁺O₄, Sb₂SnO₅,Sc₂O₃, SnO, SnO₂, SrO, SrCO₃, SrSO₄, TiO₂, UO₂, V₂O₃, VO₂, V₂O₅, VaO,Y₂O₃, YPO₄, ZnCO₃, ZnO, ZnFe₂O₄, ZnAl₂O₄, ZnS, ZrSiO₄, ZrO₂, ZrSiO₄, andany combination thereof in discrete domains and/or a substantiallyhomogeneous domain.

In some embodiments, combination of more than one salt may be used toform precipitated particles with two or more of the foregoingprecipitates in substantially homogeneous domain. For example, strontiumand barium salts may be utilized in forming precipitated particles thatcomprise (Ba,Sr)SO₄ or (Ba,Sr)CO₃. In another example, barium salts maybe used in forming precipitated particles that comprise Ba(SO₄,CrO₄).Examples of other substantially homogeneous domains may include, but arenot limited to, suitable mixtures of barium, strontium, calcium, zinc,iron, cobalt, manganese, lead, tin, and the like, and any combinationthereof in the form of sulfates, carbonates, hydroxide, oxides,sulfides, chromates and the like, and any combination thereof.

Some embodiments may involve forming precipitated particles withdiscrete domains that comprise at least one of the foregoingprecipitates. For example, a calcium carbonate particle may be formed byprecipitation and then barium salts added so as to precipitate bariumcarbonate on at least a portion of the surface of the calcium carbonateprecipitated particle. In another example, a higher specific gravitycomposition like those comprising bismuth may be precipitated and then adifferent composition precipitated thereon. Precipitating a secondcomposition on a first composition may allow for the first compositionto be formed with a desired shape and the second composition to increasethe specific gravity of the particle, which may allow for a desiredhigher specific gravity particle with a desired shape that may bedifficult to achieve otherwise. In another example, the higher specificgravity particle may be the first composition and the second compositionprecipitated thereon may enable linking of the particles or reduce theabrasiveness of the particles (described further herein).

In some embodiments, the particles produced by precipitation may becalcined to yield precipitated particles described herein. Calciningmay, inter alia, increase the mechanical properties (e.g., crushstrength) of the precipitated particles, yield a corresponding oxide(e.g., manganese carbonate to manganese oxide, calcium carbonate tocalcium oxide, bismuth carbonate to bismuth oxycarbonate or bismuthoxide, zirconium hydroxide to zirconium oxide, or magnesium hydroxide tomagnesium oxide), or any combination thereof.

In some embodiments, the precipitated particles described herein may beshaped as spherical, ovular, substantially spherical, substantiallyovular, discus, platelet, flake, toroidal (such as donut-shaped),dendritic, acicular, spiked with a substantially spherical or ovularshape (such as a sea urchin), spiked with a discus or platelet shape,rod-like, fibrous (such as high-aspect ratio shapes), polygonal (such ascubic or pyramidal), faceted (such as the shape of crystals), star orfloral shaped (such as a tripod or tetrapod where rods or the likeextend from a central point), or any hybrid thereof (e.g., adumbbell-shape). For example, spherical, ovular, substantiallyspherical, and substantially ovular-shaped precipitated particles may beuseful in producing wellbore fluids that are less abrasive to wellboretools and/or decrease viscosity as compared to ground particles. Inanother example, platelet, flake, acicular, spiked with a discus orplatelet shape, rod-like, and fibrous-shaped precipitated particles maybe useful in producing wellbore fluids with less sag and/or greaterviscosity as compared to ground particles.

It should be noted that as used herein, the terms “median diameter” and“diameter distribution” refers to a weight median diameter and a weightdiameter distribution, respectively, wherein the diameter is based onthe largest dimension of the particles. For example, rod-like particleswould have diameter distributions and the like based on the length ofthe rod-like particles. As used herein, the term “median diameter”refers to a diameter distribution wherein 50% of the particles aresmaller than a given value.

In some embodiments, the precipitated particles described herein mayhave a median diameter ranging from a lower limit of about 5 nm, 10 nm,20 nm, 50 nm, 100 nm, 250 nm, 500 nm, or 1 micron to an upper limit ofabout 100 microns, 50 microns, 25 microns, 10 microns, 5 microns, 1micron, or 750 nm, and wherein the median diameter may range from anylower limit to any upper limit and encompasses any subset therebetween.One of ordinary skill in the art should understand that precipitationmethods may be used to yield larger sizes of particles that aremillimeters or larger in size. For example, precipitated particleshaving a median diameter of about 1-10 mm may be used as proppants orlost circulation materials.

In some embodiments, the precipitated particles may be ground to achievea desired size and/or shape. Methods that involve precipitation and thengrinding may advantageously allow for production of higher purityprecipitated particles as compared to particles produced by grindingbulk minerals. Further, such methods may allow for reduced cost whilemaintaining high purity as compared to some precipitation methods withsteps to control particle size. In some instances, larger precipitatedparticles may be directly added to a mined mineral and undergo the samegrinding process such that the ground product may have a higher puritythan the mineral alone. For example, large particles of barium sulfatemay formed by precipitation and added to mined barite with high levelsof contaminants (e.g., greater than 15% sand) such that the groundproduct is higher purity, which yields a less abrasive, higher specificgravity weighting agent that is of greater value in the industry.

In some embodiments, the precipitated particles may have a narrowdiameter distribution. That is, the diameter distribution (or at leastone mode of a multimodal diameter distribution) may have a standarddeviation of about 2% or less of the peak diameter for the given mode(e.g., about 0.1% to about 2% or any subset therebetween). In someembodiments, it is believed that precipitation methods may beadvantageously employed to achieve narrow diameter distributions ofprecipitated particles described herein.

In some embodiments, the conditions under which the precipitatedparticles are formed may be manipulated so as to assist in controllingor directing the characteristics of the precipitated particles (e.g.,shape, median diameter, diameter distribution, narrow diameterdistribution, density, hardness, and the like). Examples of conditionsthat can be manipulated may include, but are not limited to, pH,temperature, chemical composition of morphology modifiers, concentrationof morphology modifiers, concentration of the salts used in theproduction of the precipitated particles, and the like, and anycombination thereof. For example, increasing the pH and/or temperaturemay increase the median diameter of the precipitated particles.

In some embodiments, forming precipitated particles may be at a pHranging from a lower limit of about 2, 3, 4, 5, 7, or 8 to an upperlimit of about 12, 11, 10, 9, 8, 7, or 6, and wherein the pH may rangefrom any lower limit to any upper limit and encompasses any subsettherebetween.

In some embodiments, forming precipitated particles may be at atemperature ranging from a lower limit of about 10° C., 20° C., 30° C.,40° C., or 50° C. to an upper limit of about 95° C., 90° C., 80° C., 70°C., or 60° C., and wherein the temperature may range from any lowerlimit to any upper limit and encompasses any subset therebetween.

As used herein, the term “morphology modifiers” refers to chemicals thatare used during the formation of precipitated particles that effect thecharacteristics of the precipitated particles. Examples of morphologymodifiers may include, but are not limited to, polymers, surfactants,electrolytes, hydrogen peroxide, silicates and other similar inorganicmaterials, aqueous-miscible organic liquids, and the like, and anycombination thereof.

Without being limited by theory, it is believed that morphologymodifiers may direct the formation of the precipitated particles in oneof at least two ways. First, the morphology modifiers may formstructures within the precipitation fluid that direct the growth of theprecipitated particle. For example, block copolymers may form micellesin aqueous solutions (e.g., spherical micelles, rod-like micelles,worm-like micelles, and the like depending on, inter alia, concentrationand pH) that direct the growth of the precipitated particles based onthe size and shape of the micelles. Second, the morphology modifiers mayinteract directly with various portions of the surface of theprecipitated particles so as to decrease or enhance growth of thatportion of the surface. This may be most prevalent in the formation ofprecipitated particles with different crystalline lattice surfaces(e.g., (101) vs (100) surfaces). For example, the inclusion ofelectrolytes like citrate may diminish growth of the precipitatedparticle on at least one crystal surface so as to yield precipitatedparticles with rod-like or flake shapes.

In some instances, both of the foregoing factors may be involved. Forexample, by varying the acidic groups of the polyethylene imine (PEI)block of a polyethylene oxide-co-polyethylene imine (PEO-co-PEI), theshape of the resultant precipitated particles can be drasticallyaltered, e.g., barium sulfate precipitated particles may bedumbbell-shaped when utilizing PEO-co-PEI-COOH, fibrous or needle-likewith PEO-co-PE₁-PO₃H₂, or floral-shaped with PEO-co-PE₁-SO₃H as comparedto a faceted structure without the polymer.

Examples of polymers that may be useful as morphology modifiers may, insome embodiments, include, but are not limited to, peptides,PEO-co-PEI-SO₃H, PEO-co-PEI-COOH, PEO-co-PE₁-PO₃H₂, PEO-co-polypropyleneoxide (PPO), PPO-co-PEO-co-PPO, PEO-co-polyethylene (PE),PPO-co-poly(methacrylic acid) (PMAA), PEO-co-poly(2-vinylpyridine)(P2VP), P2VP-co-polyacrylic acid (PAA), PMMA-co-PAA, polystyrenesulfonate (PSS), PEO, PPO, PE₁, PE₁-SO₃H, PEI-COOH, PE₁-PO₃H₂, PMAA, andthe like, salts thereof where appropriate, any derivative thereof, andany combination thereof. Additional examples of polymers that may beuseful as morphology modifiers may, in some embodiments, include, butare not limited to, homopolymers or copolymers of monomers selected fromthe group comprising: acrylic acid, itaconic acid, maleic acid oranhydride, hydroxypropyl acrylate vinylsulphonic acid, acrylamido2-propane sulphonic acid, acrylamide, methacrylamide, hydrolyzedacrylamide, styrene sulphonic acid, acrylic phosphate esters, methylvinyl ether, vinyl acetate, stearyl methacrylate, butylacrylate, vinylpyrrolidone, glycols (ethylene glycol, propylene glycol, and butyleneglycol), and the like, salts thereof where appropriate, any derivativethereof, and any combination thereof. Examples of commercially availablepolymers may include Pluronic® surfactants (polyethyleneoxide-polypropylene oxide-polyethylene oxide triblock polymers,available from BASF), Tetronic® surfactants (tetra-functional blockcopolymers based on ethylene oxide and propylene oxide, available fromBASF), and the like, and any combination thereof. In some embodiments,when polymers are used in the formation of precipitated particles, theresultant particles may be at least partially coated with the polymers.

In some embodiments, molecular weight of the polymer may effect thecharacteristics of the resultant precipitated particle. For example, PSSpolymers used in the synthesis of precipitated particles (e.g.,carbonate particles) may be more spherical with higher molecular weightPSS. In some embodiments, the molecular weight of polymers used asmorphology modifiers in the formation of precipitated particles mayrange from a lower limit of about 10,000 g/mol, 25,000 g/mol, 100,000g/mol, or 250,000 g/mol to an upper limit of about 2,000,000 g/mol,1,000,000 g/mol, 500,000 g/mol, or 250,000 g/mol, and wherein themolecular weight may range from any lower limit to any upper limit andencompasses any subset therebetween.

In some embodiments, the concentration of polymers used as morphologymodifiers in the formation of precipitated particles may range from alower limit of about 0.1 g/L, 1 g/L, or 5 g/L to an upper limit of about100 g/L, 25 g/L, 10 g/L, or 5 g/L, and wherein the concentration mayrange from any lower limit to any upper limit and encompasses any subsettherebetween.

Examples of surfactants that may be useful as morphology modifiers may,in some embodiments, include, but are not limited to, oleic acid,monobasic fatty acids, polybasic fatty acids, alkylbenzene sulfonicacids, alkane sulfonic acids, linear alpha-olefin sulfonic acid,phospholipids, betaines, and the like, salts thereof where appropriate,any derivative thereof, and any combination thereof. Examples ofcommercially available surfactants may include Brij® surfactants(ethoxylated fatty alcohols, available from Sigma-Aldrich), Triton®surfactants (ethoxylated fatty alkylphenols, available fromSigma-Aldrich), and the like, and any combination thereof.

In some embodiments, the concentration of surfactants used as morphologymodifiers in the formation of precipitated particles may range from alower limit of about 0.1 g/L, 1 g/L, or 5 g/L to an upper limit of about100 g/L, 25 g/L, 10 g/L, or 5 g/L, and wherein the concentration mayrange from any lower limit to any upper limit and encompasses any subsettherebetween.

Examples of aqueous-miscible organic liquids that may be useful asmorphology modifiers may, in some embodiments, include, but are notlimited to, acetone, dimethyl formamide, methanol, ethanol, n-propanol,isopropanol, n-butanol, sec-butanol, isobutanol, t-butanol, glycerol,pyridine, tetrahydrofuran, and the like.

In some embodiments, the concentration of aqueous-miscible organicliquids used as morphology modifiers in the formation of precipitatedparticles may range from a lower limit of about 1%, 10%, or 25% byvolume of the precipitation fluid to an upper limit of about 98%, 75%,or 50% by volume of the precipitation fluid, and wherein theconcentration may range from any lower limit to any upper limit andencompasses any subset therebetween.

In some embodiments, multiple morphology modifiers may be manipulated toachieve precipitated particles with desired characteristics. By way ofnonlimiting example, hydrogen peroxide concentration and pH may beadjusted to change the surface of precipitated particles, e.g., withrespect to calcium carbonate precipitated particles, higher pH values(e.g., about 11) and higher hydrogen peroxide concentrations may yieldcalcium carbonated precipitated particles with smaller facetedprotrusions (or spikes) on the surface as compared to a lower pH (e.g.,about 9) and lower hydrogen peroxide concentrations that may yieldlarger, smoother facets along the surface of the precipitated particle.Further, the precipitation time may be adjusted to allow for particlefusion to yield dumbbell or peanut-shaped precipitated particles thatdepending on the pH and hydrogen peroxide concentration may have largefaceted surfaces or small faceted protrusions.

In some embodiments of the present invention, wellbore additives and/orwellbore fluids may comprise the precipitated particles describedherein. Such wellbore additives and/or wellbore fluids may be used inconjunction with a plurality of wellbore operations. As used herein, theterms “wellbore additive” and “wellbore fluid” refer to any additive orfluid, respectively, suitable for use in conjunction with a wellborepenetrating a subterranean formation and does not imply any particularaction by the additive or fluid. Similarly, the term “wellboreoperation” refers to any treatment or operation suitable for use inconjunction with a wellbore and/or subterranean formation, e.g.,drilling operations, lost circulation operations, fracturing operations,cementing operations, completion operations, and the like.

In some embodiments, the wellbore additives and/or the wellbore fluidsmay comprise the precipitated particles described herein having amultimodal diameter distribution (e.g., bimodal, trimodal, and so on).In some embodiments, the wellbore additives and/or the wellbore fluidsmay comprise the precipitated particles described herein having amultimodal diameter distribution such that at least one mode has anmedian diameter (or peak diameter) ranging from a lower limit of about 5nm, 10 nm, 20 nm, 50 nm, 100 nm, 250 nm, 500 nm, or 1 micron to an upperlimit of about 50 microns, 10 microns, 5 microns, 1 micron, or 500 nmand at least one mode has an median diameter ranging from a lower limitof about 10 microns, 25 microns, 50 microns, or 100 microns to an upperlimit of about 5000 microns, 2500 microns, 1000 microns, 500 microns,100 microns, or 50 microns, and wherein each mode may range from anycorresponding lower limit to any corresponding upper limit such that atleast two distinct modes are present and each range encompasses anycorresponding subset therebetween. By way of nonlimiting example, FIGS.1A-B illustrate theoretical multimodal diameter distributions for use inwellbore fluids. FIG. 1A illustrates a bimodal diameter distributionwith a first mode median diameter of about 1 micron and a second modemedian diameter of about 25 microns. FIG. 1B illustrates a trimodaldiameter distribution with a first mode median diameter of about 5microns, a second mode median diameter of about 50 microns, and a thirdmode median diameter of about 90 microns.

In some embodiments, the mode(s) of a diameter distribution mayindependently be considered to have a narrow diameter distribution. Thatis, at least one mode of a diameter distribution (including monomodal)may have a standard deviation of about 2% or less of the peak diameterfor the given mode (e.g., about 0.1% to about 2% or any subsettherebetween). In some embodiments, it is believed that precipitationmethods may be advantageously employed to achieve narrow diameterdistributions of precipitated particles described herein.

The precipitated particles described herein may be added to a wellborefluid to achieve a desired density of the wellbore fluid. In someembodiments, the wellbore fluids described herein may have a densitybetween a lower limit of about 7 pounds per gallon (“ppg”), 9 ppg, 12ppg, 15 ppg, or 22 ppg to an upper limit of about 50 ppg, 40 ppg, 30ppg, 22 ppg, 20 ppg, or 17 ppg, and wherein the density of the wellborefluid may range from any lower limit to any upper limit and encompassesany subset therebetween. One of ordinary skill in the art shouldunderstand that the ability to achieve a desired density of the wellborefluid while maintaining a fluid that can be pumped may depend on, interalia, the composition and specific gravity of the precipitatedparticles, the shape of the precipitated particles, the concentration ofthe precipitated particles, and the like, and any combination thereof.For example, wellbore fluids having a density of about 25 ppg or highermay be achieved with precipitated particles having a specific gravity ofabout 7 or greater (e.g., BiO₃ and/or Bi₂O₃) and having a shape ofspherical, substantially spherical, ovular, substantially ovular, or ahybrid thereof so as to allow for the fluid to be pumpable. In anotherexample, wellbore fluids having a density of about 30 ppg or less may beachieved with precipitated particles having a specific gravity of about7 or greater and having a larger variety of shapes, including discus.

In some embodiments, a mixture of two or more types of precipitatedparticles (or a mixture of precipitated and non-precipitated particles)described herein having a multiparticle specific gravity may be added toa wellbore fluid for a desired density. As used herein, the term“multiparticle specific gravity” refers to the calculated specificgravity from Formula I.

multiparticle specific gravity=vol % A*sg_(A)+vol % B*sg_(B)+ . . . vol% n*sg_(n)  Formula I:

-   -   wherein vol % is the volume percent of particle relative to the        total volume of the particles used as weighting agent, sg is the        specific gravity of the particle, A is the first particle, B is        the second particle, and n is the n^(th) particle

In some embodiments, the wellbore additives and/or the wellbore fluidsmay comprise a mixture of precipitated particles described herein havinga multiparticle specific gravity ranging from a lower limit of about 3,4, 4.5, 5, or 5.5 to an upper limit of about 20, 15, 10, 9, 8, or 7, andwherein the multiparticle specific gravity may range from any lowerlimit to any upper limit and encompasses any subset therebetween. One ofordinary skill in the art with the benefit of this disclosure shouldunderstand that when specific gravity is referred to in combination withmultiple precipitated particles, specific gravity refers to themultiparticle specific gravity. In some embodiments, the mixture ofprecipitated particles may comprise at least one precipitated particleand at least one non-precipitated particle (e.g., formed by grindingmethods only). Examples of non-precipitated particles may include, butare not limited to, particles having a specific gravity greater thanabout 2.6 comprising at least one of BaSO₄, CaCO₃, (Ca,Mg)CO₃, FeCO₃,Fe₂O₃, α-Fe₂O₃, α-FeO(OH), Fe₃O₃, FeTiO₃, (Fe,Mg)SiO₄, SrSO₄, MnO, MnO₂,Mn₂O₃, Mn₃O₃, Mn₂O₇, MnO(OH), (Mn²⁺,Mn³⁺)₂O₄, barite, calcium carbonate,dolomite, hematite, siderite, magnetite, manganese dioxide, manganese(IV) oxide, manganese oxide, manganese tetraoxide, manganese (II) oxide,manganese (III) oxide, AgI, AgCl, AgBr, AgCuS, AgS, Ag₂S, Ag₃SbS₃,AgSbS₂, AgSbS₂, AgsSbS₄, (AgFe₂S₃), Ag₃AsS₃, Ag₃AsS₃,Cu(Ag,Cu)₆Ag₉As₂S₁₁, [(Ag,Cu)₆(Sb,As)₂S₇][Ag₉CuS₄], Ag₃AuTe₂,(Ag,Au)Te₂, Ag₂Te, Al₂O₃, Al₂SiO₅, AsSb, (Co,Ni,Fe)As₃, PtAs₂, AuTe₂,BaCO₃, BaO, BeO, Bi, BiOCl, (BiO)₂CO₃, BiO₃, Bi₂S₃, Bi₂O₃, CaO, CaF₂,CaWO₄, CdS, CdTe, Ce₂O₃, CoAsS, Co⁺²C⁺³ ₂S₄, (Fe,Mg)Cr₂O₄, Cr₂O₃, Cu,CuO, Cu₂O, CuS, Cu₂S, CuS₂, Cu₉S₅, CuFeS₂, Cu₅FeS₄, CuS.Co₂S₃,Cu₃AsO₄(OH)₃, Cu₃AsS₄, Cu₁₂As₄S₁₃, Cu₂(AsO₄)(OH), CuPb₁₃Sb₇S₂₄,CuSiO₃.H₂O, Fe₃Al₂(SiO₄)₃, Fe²⁺Al₂O₄, Fe₂SiO₄, FeWO₄, FeAs₂, FeAsS, FeS,FeS₂, Fe_((1-x))S (wherein x=0 to 0.2), (Fe,Ni)₉S₈, Fe²⁺Ni₂ ³⁺S₄,(Fe,Mn)WO₄, Fe²⁺ Nb₂O₆, (Mn,Fe,Mg)(Al,Fe)₂O₄, CaFe²⁺ ₂Fe³⁺Si₂O₇O(OH),(YFe³⁺Fe²⁺U,Th,Ca)₂(Nb,Ta)₂O₈, HgS, Hg₂Cl₂, MgO, MnCO₃, Mn₂S, Mn₂SiO₄,MnWO₄, Mn(II)₃Al₂(SiO₄)₃, (Na_(0.3)Ca_(0.1)K_(0.1))(Mn⁴⁺,Mn³⁺)₂O₄.1.5H₂O, (Mn,Fe)₂O₃, (Mn²⁺,Fe²⁺,Mg)(Fe³⁺,Mn³⁺)₂O₄, (Mn²⁺,Mn³⁺)₆[O₈|SiO₄],Ca(Mn³⁺,Fe³⁺)₁₄SiO₂₄, Ba(Mn²⁺)(Mn⁴⁺)₈O₁₆(OH)₄, CaMoO₄, MoS₂, MOO₂, MOO₃,NbO₄, (Na,Ca)₂Nb₂O₆(OH,F), (Y,Ca,Ce,U,Th)(Nb,Ta,Ti)₂O₆,(Y,Ca,Ce,U,Th)(Ti,Nb,Ta)₂O₆, (Fe,Mn)(Ta,Nb)₂O₆, (Ce,La)PO₄,(Ce,La,Ca)BSiO₅, (Ce,La)CO₃F, (Y,Ce)CO₃F, (U,Ca,Y,Ce)(Ti,Fe)₂, NiO,NiAs₂, NiAs, NiAsS, Ni_(x)Fe(x=2-3), (Ni, Co)₃S₄, NiS, PbTe, PbSO₄,PbCrO₄, PbWO₄, PbSiO₃, PbCO₃, (PbCl)₂CO₃, Pb₅(PO₄)₃Cl, Pb₅(AsO₄)₃Cl,Pb²⁺ ₂Pb⁴⁺O₄, Pb₅Au(Te,Sb)₄S₅₋₈, Pb₅Sb₈S₁₇, PbS, Pb₉Sb₈S₂₁,Pb₁₄(Sb,As)₆S₂₃, Pb₅Sb₄S₁₁, Pb₄FeSb₆S₁₄, PbCu[(OH)₂|SO₄], PbCuSbS₃,(Cu,Fe)₁₂Sb₄S₁₃, Sb₂S₃, (Sb³⁺,Sb⁵⁺)O₄, Sb₂SnOs₅, Sc₂O₃, SnO, SnO₂,Cu₂FeSnS₄, SrO, SrCO₃, (Na, Ca)₂Ta₂O₆(O,OH,F), ThO₂, (Th,U)SiO₄, TiO₂,UO₂, V₂O₃, VO₂, V₂O₅, Pb₅(VO₄)₃Cl, VaO, Y₂O₃, YPO₄, ZnCO₃, ZnO, ZnFe₂O₄,ZnAl₂O₄, ZnCO₃, ZnS, ZnO, (Zn_((1-x))Fe_((x))S), (Zn,Fe)S, ZrSiO₄, ZrO₂,ZrSiO₄, acanthite, alamandite, allemontite, altaite, aluminum oxide,andalusite, anglesite, antimony sulfide, antimony tin oxide, antimonytrioxide, argentite, arsenopyrite, awaruite, barium carbonate, bariumoxide, bastnaesite, beryllium oxide, birnessite, bismite, bismuth,bismuth oxycarbonates, bismuth oxychloride, bismuth sulfide, bismuthsulfide, bismuth trioxide, bismuth (III) oxide, bixbyite, bornite,boulangerite, bournonite, brannerite, braunite, bravoite, bromyrite,cadimum sulfide, cadimum telluride, calayerite, calcium oxide, calomel,carrollite, cassiterite, celestine, cerargyrite, cerium oxide,cerussite, cervantite, chalcocite, chalcopyrite, chromite, chromiumoxide, cinnabar, clinoclase, cobaltite, columbite, copper, copper oxide,copper sulfide, corundum, covellite, crocoite, cuprite, danaite,digenite, embolite, enargite, euxenite, fayalite, ferberite,fergusonite, ferrous sulfide, franklinite, gahnite, galaxite, galena,geocronite, geothite, gersdorffite, greenockite, hausmmanite, hercynite,hessite, huebnerite, ilmenite, ilvaite, iodyrite, iridosmine, Jacobsite,Jamesonite, krennerite, larsenite, linarite, linnaeite, loellingite,magnesium oxide, manganese carbonate, manganite, manganosite, marcasite,marmatite, menaghinite, miargyrite, microlite, millerite, mimetite,minium, molybdenite, molybdenum (IV) oxide, molybdenum oxide, molybdenumtrioxide, monazite, nagyagite, niccolite, nickel oxide, pearceite,pentlandite, perovskite, petzite, phosgenite, phyromorphite, plagionite,polianite, polybasite, polycrase, powellite, proustite, psilomelane,pyrargyrite, pyrite, pyrochlore, pyrolusite, pyrrhotite, rammelsbergite,rutile, samarskite, scandium oxide, scheelite, semsyite, siegenite,skutterudite, smithsonite, spalerite, sperrylite, spessartite,sphalerite, stannite, stephanite, sternbergite, stibnite, stillwellite,stolzite, Stromeyerite, strontium oxide, sylvanite, tantalite,tennantite, tenorite, tephroite, tetrahedrite, thorianite, thorite, tindioxide, tin (II) oxide, titanium dioxide, turgite, uraninite,vanadinite, vanadium oxide, vanadium trioxide, vanadium (IV) oxide,vanadium (V) oxide, violarite, witherite, wolframite, wulfenite,wurtzite, xenotime, yttrium oxide, zinc carbonate, zincite, zinkenite,zircon, zirconium oxide, zirconium silicate, zinc oxide, and suitablecombinations thereof.

The precipitated particles (optionally in combination withnon-precipitated particle) may be present in the wellbore fluid in anamount sufficient for a particular application. In certain embodiments,the precipitated particles may be present in a wellbore fluid in anamount up to about 70% by volume of the wellbore fluid (v %) (e.g.,about 5 v %, about 15 v %, about 20 v %, about 25 v %, about 30 v %,about 35 v %, about 40 v %, about 45 v %, about 50 v %, about 55 v %,about 60 v %, about 65 v %, etc.). In certain embodiments, theprecipitated particles may be present in the wellbore fluid in an amountof 10 v % to about 40 v %.

As described above, the precipitated particles described herein may havetailored characteristics that can be exploited to achieve desiredproperties and/or capabilities in a wellbore fluid beyond density, e.g.,sag control. Particles (e.g., weighting agents, proppants, and cementparticles) in wellbore fluids can settle from or migrating within thewellbore fluid therein, which is a condition known as “sag.” As usedherein, the term “sag” refers to an inhomogeneity in density of a fluidin a wellbore, e.g., along the length of a wellbore and/or the diameterof a deviated wellbores. In some instances, sag can cause to portions ofthe wellbore fluid to be at an insufficient density to stabilize thewellbore and other portions of the wellbore fluid to have increaseddensity. Unstabilized portions of the wellbore can lead to wellborecollapse and/or pressure buildups that cause blowouts. Increased densitycan cause wellbore damage (e.g., undesired fracturing of the wellbore),which may show up as pressure increases or decreases when changing fromstatic to flow conditions of the fluid which can cause higher thandesired pressures downhole.

In some embodiments, the precipitated particles described herein may besized, shaped, or otherwise treated (e.g., coated) so as to mitigate sagin wellbore fluids. The size may, inter alia, provide for the formationof a stable suspension that exhibit low viscosity under shear. Further,the specific gravity of the precipitated particles may further allow forsuch precipitated particles to provide for a desired density of thewellbore fluid while mitigating sag of these precipitated particles orother particles therein.

Sag control can be measured by analyzing density changes in anundisturbed sample of wellbore fluid over time at a typical wellboretemperature (e.g., about 300° F.) and an elevated pressure (e.g., about5,000 psi to about 10,000 psi). For example, the precipitated particlesdescribed herein that provide effective sag control may, in someembodiments, yield wellbore fluids having a change in density of lessthan about 1 ppg (e.g., about 0.5 ppg change or less including no changein density) when comparing a fluid's original density to the fluid'sdensity at the bottom of a sample having been undisturbed for a givenamount of time. In some embodiments, the precipitated particlesdescribed herein may provide sag control (i.e., a density change of lessthan about 1 ppg) over a time ranging from a lower limit of about 10hours, 24 hours, 36 hours, or 48 hours to an upper limit of about 120hours, 96 hours, 72 hours, or 48 hours, and wherein the sag controltimeframe of the wellbore fluid may range from any lower limit to anyupper limit and encompasses any subset therebetween.

In some embodiments, the properties of the precipitated particlesdescribed herein may be tailored to achieve sag control. Properties ofthe precipitated particles that can be tailored to achieve sag controlmay include, but are not limited to, size (e.g., median diameter ofabout 2 microns or less or at least one mode of a multimodaldistribution having such a peak diameter), shape (e.g., particle shapeswith lower sphericity like discus, platelet, flake, acicular, spikedwith a substantially spherical or ovular shape, spiked with a discus orplatelet shape, fibrous, toroidal, and the like), coatings, linking(described further herein), and the like, and any combination thereof.

In some embodiments, when using two or more precipitated particles withdifferent specific gravities to produce a homogeneous wellbore fluid,the size and shape of each of the precipitated particles may be tailoredso as to minimize separation of the precipitated particles, which maylead to a wellbore fluid with a striated density profile. For example, afirst precipitated particle with a discus or platelet shape may impedethe settling of a second precipitated particle that has a high settlingor migration rate (e.g., a higher specific gravity, spherical particle).

In some embodiments, the properties of the precipitated particlesdescribed herein may be tailored to mitigate the abrasion of wellboretools (e.g., pumps, drill bits, drill string, and a casing) as comparedto comparable API grade barite (i.e., a comparable wellbore fluid havingthe same density and/or sag as the wellbore fluid comprising theprecipitated particles), which may prolong the life of the wellboretools. It should be noted that the term “wellbore tools” encompassestools suitable for use in conjunction with wellbore operations,including tools that are used outside of the wellbore, e.g., pumps,shakers, and the like. Abrasion can be measured by the ASTM G75-07 andis reported as a Miller Number or a SAR Number.

Suitable precipitated particles can be those with properties tailored tomitigate abrasion, which may include, but are not limited to, hardness(e.g., a Mohs hardness of less than about 5), size (e.g., mediandiameter less than about 400 nm or mode of a multimodal distributionhaving an peak diameter less than about 400 nm), shape (e.g., particleshapes with higher sphericity like spherical, substantially spherical,ovular, substantially ovular, and the like), coatings (e.g., thickerand/or elastic coatings that minimize physical interactions between themineral portion of the precipitated particle and the wellbore tool), andthe like, and any combination thereof. For example, the wellbore fluidsmay comprise substantially spherical awaruite particles with a mediandiameter less than about 400 nm and manganese carbonate particles, whichhave a Mohs hardness less than about 5.

At least some of the precipitated particles described herein may, insome embodiments, be capable of being linked by linking agents. Linkingof precipitated particles may allow for increasing the viscosity of thewellbore fluid or forming a solid mass described further herein. Oneskilled in the art with the benefit of this disclosure should recognizethat, inter alia, the composition of the precipitated particlesdescribed herein may determine if the precipitated particles aresuitable for being linked and to what degree they can be linked.Examples of linkable precipitated particles may include, but are notlimited to, those that comprise at least one of Al₂O₃, BaCO₃, BaO, BeO,(BiO)₂CO₃, BiO₃, Bi₂O₃, CaO, CaCO₃, (Ca,Mg)CO₃, CdS, CdTe, Ce₂O₃, Cr₂O₃,CuO, Cu₂O, Fe^(2+Al) ₂O₄, Fe₂SiO₄, FeCO₃, Fe₂O₃, α-Fe₂O₃, α-FeO(OH),Fe₃O₃, FeTiO₃, MgO, MnCO₃, MnO, MnO₂, Mn₂O₃, Mn₃O₃, Mn₂O₇, MnO(OH),CaMoO₄, MoS₂, MOO₂, MOO₃, NbO₄, NiO, NiAs₂, NiAs, NiAsS, NiS, PbCO₃,(PbCl)₂CO₃, Sb₂SnO₅, Sc₂O₃, SnO, SnO₂, SrO, SrCO₃, SrSO₄, TiO₂, UO₂,V₂O₃, VO₂, V₂O₅, VaO, Y₂O₃, YPO₄, ZnCO₃, ZnO, ZnFe₂O₄, ZnAl₂O₄, ZrSiO₄,ZrO₂, ZrSiO₄, and any combination thereof. Additionally, in precipitatedparticles with discrete domains, precipitated particles having any ofthe foregoing in a domain accessible to be linked may also be suitable.

Examples of linking agents suitable for use in conjunction with theprecipitated particles may, in some embodiments, include, but are notlimited to, eugenol, guaiacol, methyl guaiacol, salicyladehyde,salicyladimine, salicylic acid, sodium salicylate, acetyl salicylicacid, methyl salicylic acid, methyl acetylsalicylic acid, anthranilicacid, acetyl anthranilic acid, vanillin, derivatized1,2-dihydroxybenzene (catechol), derivatized or unsubstituted phthalicacid, ortho-phenylenediamine, ortho-aminophenol,ortho-hydroxyphenylacetic acid, alkylsilanes, esters, ethers, and thelike, and any combination thereof. Additionally polymers of theforegoing examples, or suitable derivatives thereof, may used as linkingagents. For example, vinyl derivatives of the foregoing examples may beused in synthesizing a polymer or copolymer suitable for use as alinking agents. In another example, carboxylated derivates of theforegoing examples may be used in derivatizing a polyamine to yieldsuitable linking agents. Additional examples may include, but are notlimited to, compounds (including polymers and lower molecular weightmolecules) having at least two silane moieties, ester moieties, ethermoieties, sulfide moieties, amine moieties, and the like, and anycombination thereof.

Viscosity increases from linking with linking agents may, in someembodiments, yield wellbore fluids that remain pumpable, wellbore fluidsthat are non-pumpable, or hardened masses. One skilled in the art withthe benefit of this disclosure should understand that the extent of theviscosity increase may depend on, inter alia, the composition of theprecipitated particles described herein, the composition of the linkingagents, the relative concentration of the precipitated particles and thelinking agents, intended use, additional components in the wellborefluid, and any combination thereof.

In some embodiments, the precipitated particles described herein mayadvantageously have a higher unconfined compressive strength (e.g.,about 1200 psi or greater) that allow for load-bearing applications(e.g., proppant applications). In some embodiments, the precipitatedparticles described herein may advantageously have a moderate to highunconfined compressive strength (e.g., about 500 psi or greater) thatallow for implementation in applications like cements, wellborestrengthening additives, and gravel packs. The unconfined compressivestrength of a precipitated particle may depend on, inter alia, thecomposition of the precipitated particle, the shape of the precipitatedparticle, additional processing steps in producing the precipitatedparticle (e.g., calcining after precipitation), and the like, and anycombination thereof.

While a plurality of the precipitated particles described herein mayhave high compressive strength, in some preferred embodiments, suchprecipitated particles may comprise at least one of Al₂O₃, CaF₂, CaWO₄,CaCO₃, (Ca,Mg)CO₃, CuO, Cu₂O, CuS, Cu₂S, CuS₂, Cu₉S₅, CuFeS₂, Cu₅FeS₄,CuS.Co₂S₃, Fe²⁺Al₂O₄, Fe₂SiO₄, FeWO₄, FeS, FeS₂, FeCO₃, Fe₂O₃, α-Fe₂O₃,α-FeO(OH), Fe₃O₃, FeTiO₃, MnCO₃, Mn₂S, MnWO₄, MnO, MnO₂, Mn₂O₃, Mn₃O₃,Mn₂O₇, MnO(OH), CaMoO₄, MOO₂, MoO₃, NiO, NiS, SnO, SnO₂, TiO₂, ZnCO₃,ZnO, ZnFe₂O₄, ZnAl₂O₄, ZnS, ZrSiO₄, ZrO₂, ZrSiO₄, and any combinationthereof.

At least some of the precipitated particles described herein may, insome embodiments, be at least partially degradable. As used herein, theterm “degradable” refers to a material being capable of reduced in sizeby heterogeneous degradation (or bulk erosion) and homogeneousdegradation (or surface erosion), and any stage of degradation inbetween these two. This degradation can be a result of, inter alia, achemical or thermal reaction, for example, dissolution by an acidicfluid. One skilled in the art with the benefit of this disclosure shouldrecognize that, inter alia, the composition of the precipitatedparticles described herein may determine if the precipitated particlesare degradable and to what extent they are degradable.

While a plurality of the precipitated particles described herein mayhave be degradable, in some preferred embodiments, degradableprecipitated particles may comprise at least one of BaCO₃, (BiO)₂CO₃,CaWO₄, CaCO₃, CuO, FeCO₃, PbCO₃, (PbCl)₂CO₃, SrCO₃, ZnCO₃, and anycombination thereof.

Degradation of the precipitated described herein may advantageously beused in a plurality of wellbore operations, e.g., cleanup operations(e.g., in removing a filter cake or plug from a lost circulationoperation) and cementing operations (e.g., in enhancing the permeabilityof a cement plug to allow for fluid to flow therethrough while stillproviding structural strength). Additionally, degradation may beadvantageous in reducing the viscosity of a fluid by degradingprecipitated particles that contribute to the viscosity (e.g., by shapeand/or by linking).

Examples of degradation agents that may be useful in at least partiallydegrading precipitated particles described herein may, in someembodiments, include, but are not limited to, acid sources (e.g.,inorganic acids, organic acid, and polymers that degrade into acids likepolylactic acid), alkaline sources (e.g., bases), and oxidizers (e.g.,peroxide compounds, permanganate compounds, and hexavalent chromiumcompounds).

In some embodiments, the precipitated particles described herein may bechosen so as to degrade over a desired amount of time, which may bedependent on, inter alia, particle size, particle shape, wellboretemperature, and precipitated particle composition. For example, calciumcarbonate rather than lead carbonate may be utilized, in someembodiments, when for faster degradation. In another example, manganesecarbonate may, in some embodiments, be chosen for slower degradation incolder wellbore environments and faster degradation in hotter wellboreenvironments.

In some embodiments, the precipitated particles described herein mayhave a coating on at least a portion of the surface of the precipitatedparticles. As used herein, the term “coating,” and the like, does notimply any particular degree of coating on the particle. In particular,the terms “coat” or “coating” do not imply 100% coverage by the coatingon the particle. Further, a coating may, in some embodiments, becovalently and/or noncovalently associate with the precipitatedparticles described herein.

In some embodiments, a coating suitable for use in conjunction with theprecipitated particles described herein may include, but are not limitedto, polymers, surfactants, and any combination thereof. Coatings may, insome embodiments, assist in the suspension of the precipitated particlesand/or the compatibility of the precipitated particles with a wellborefluid and/or wellbore operation. For example, a coating like an alkylamine may, in some embodiments, associate with the surface of theprecipitated particles so as to render the precipitated particle morehydrophobic, which may enhance the suspendability of the precipitatedparticles in oil-based fluids.

In some embodiments, precipitated particles may be coated after additionto the wellbore fluid.

In some embodiments, a coating may be applied during production of theprecipitated particles described herein. For example, grindingproduction methods may, in some embodiments, be conducted in thepresence of polymers, surfactants, or the like suitable for use as acoating. Additionally, in some embodiments, precipitation productionmethods may be conducted in the presence of polymers, surfactants, orthe like suitable for use as a coating. One skilled in the art with thebenefit of this disclosure should understand that including polymers,surfactants, or the like in a production method of the precipitatedparticles described herein should be chosen so as not to significantlyimpact the production in a negative manner.

Polymers suitable for use in conjunction with the coated precipitatedparticles described herein may, in some embodiments, have a molecularweight ranging from a lower limit of about 10,000 g/mol, 25,000 g/mol,100,000 g/mol, or 250,000 g/mol to an upper limit of about 2,000,000g/mol, 1,000,000 g/mol, 500,000 g/mol, or 250,000 g/mol, and wherein themolecular weight may range from any lower limit to any upper limit andencompasses any subset therebetween.

In some embodiments, coating may comprise the polymers list herein thatmay be useful as morphology modifiers. In some embodiments, the polymersmay be used as morphology modifiers any yield coated precipitatedparticles. In other instances, the precipitated particles may be formedand then polymers suitable for use as morphology modifiers may be usedas coatings.

In some embodiments, coatings may comprise consolidating agents thatgenerally comprise any compound that is capable of minimizingparticulate migration once placed, which may be suitable for methods andcompositions relating to proppant packs, gravel packs, and the like.Suitable consolidating agents may include, but are not limited to,non-aqueous tackifying agents, aqueous tackifying agents, emulsifiedtackifying agents, silyl-modified polyamide compounds, resins,crosslinkable aqueous polymer compositions, polymerizable organicmonomer compositions, consolidating agent emulsions, zeta-potentialmodifying aggregating compositions, silicon-based resins, and binders.Combinations and/or derivatives of these also may be suitable.Nonlimiting examples of suitable non-aqueous tackifying agents may befound in U.S. Pat. Nos. 7,392,847, 7,350,579, 5,853,048; 5,839,510; and5,833,000, the entire disclosures of which are herein incorporated byreference. Nonlimiting examples of suitable aqueous tackifying agentsmay be found in U.S. Pat. Nos. 8,076,271, 7,131,491, 5,249,627 and4,670,501, the entire disclosures of which are herein incorporated byreference. Nonlimiting examples of suitable crosslinkable aqueouspolymer compositions may be found in U.S. Patent Application PublicationNo. 2010/0160187 and U.S. Pat. No. 8,136,595 the entire disclosures ofwhich are herein incorporated by reference. Nonlimiting examples ofsuitable silyl-modified polyamide compounds may be found in U.S. Pat.No. 6,439,309 entitled the entire disclosure of which is hereinincorporated by reference. Nonlimiting examples of suitable resins maybe found in U.S. Pat. Nos. 7,673,686; 7,153,575; 6,677,426; 6,582,819;6,311,773; and 4,585,064 as well as U.S. Patent Application PublicationNo. 2008/0006405 and U.S. Pat. No. 8,261,833, the entire disclosures ofwhich are herein incorporated by reference. Nonlimiting examples ofsuitable polymerizable organic monomer compositions may be found in U.S.Pat. No. 7,819,192, the entire disclosure of which is hereinincorporated by reference. Nonlimiting examples of suitableconsolidating agent emulsions may be found in U.S. Patent ApplicationPublication No. 2007/0289781 the entire disclosure of which is hereinincorporated by reference. Nonlimiting examples of suitablezeta-potential modifying aggregating compositions may be found in U.S.Pat. Nos. 7,956,017 and 7,392,847, the entire disclosures of which areherein incorporated by reference. Nonlimiting examples of suitablesilicon-based resins may be found in Application Publication Nos.2011/0098394, 2010/0179281, and U.S. Pat. Nos. 8,168,739 and 8,261,833,the entire disclosures of which are herein incorporated by reference.Nonlimiting examples of suitable binders may be found in U.S. Pat. Nos.8,003,579; 7,825,074; and 6,287,639, as well as U.S. Patent ApplicationPublication No. 2011/0039737, the entire disclosures of which are hereinincorporated by reference. It is within the ability of one skilled inthe art, with the benefit of this disclosure, to determine the type andamount of consolidating agent to include in the methods of the presentinvention to achieve the desired results.

In some embodiments, the wellbore additives may comprise theprecipitated particles described herein and optionally further compriseother particles and/or additional components suitable for use in aspecific wellbore operation (e.g., proppants and cement particles asdescribed further herein). Wellbore additives may, in some embodiments,be dry powder or gravel, a liquid with a high concentration of theprecipitated particles described herein (e.g., a slurry), and the like.

As described herein, in some embodiments, it may be advantageous toinclude a combination of types of precipitated particles describedherein so as to achieve a wellbore fluid with desired properties and/orcapabilities. The ratio of the various particles may depend on, interalia, the desired properties and/or characteristics of the wellborefluid.

Distinctions between types of precipitated particles may, in someembodiments, be defined by at least one of mineral composition,production method, median diameter, diameter distribution, presence orabsence of coating, coating composition, and the like, and anycombination thereof. As such, achieving homogeneous mixtures of drywellbore additives may be aided by inclusion of a dry lubricant tofacilitate homogeneous mixing and flowability. Examples of dry lubricantmay, in some embodiments, include, but are not limited to, molybdenumdisulfide, graphite, boron nitride, tungsten disulfide,polytetrafluoroethylene particles, bismuth sulfide, bismuth oxychloride,and the like, and any combination thereof. In some embodiments, a drylubricant may advantageously have a specific gravity greater than about2.6 (e.g., molybdenum disulfide, tungsten disulfide, bismuth sulfide,and bismuth oxychloride) so as contribute to the density of theresultant wellbore fluid.

Examples of base fluids suitable for use in conjunction with thewellbore fluids may, in some embodiments, include, but are not limitedto, oil-based fluids, aqueous-based fluids, aqueous-miscible fluids,water-in-oil emulsions, or oil-in-water emulsions. Suitable oil-basedfluids may include alkanes, olefins, aromatic organic compounds, cyclicalkanes, paraffins, diesel fluids, mineral oils, desulfurizedhydrogenated kerosenes, and any combination thereof. Suitableaqueous-based fluids may include fresh water, saltwater (e.g., watercontaining one or more salts dissolved therein), brine (e.g., saturatedsalt water), seawater, and any combination thereof. Suitableaqueous-miscible fluids may include, but not be limited to, alcohols,e.g., methanol, ethanol, n-propanol, isopropanol, n-butanol,sec-butanol, isobutanol, and t-butanol; glycerins; glycols, e.g.,polyglycols, propylene glycol, and ethylene glycol; polyglycol amines;polyols; any derivative thereof; any in combination with salts, e.g.,sodium chloride, calcium chloride, calcium bromide, zinc bromide,potassium carbonate, sodium formate, potassium formate, cesium formate,sodium acetate, potassium acetate, calcium acetate, ammonium acetate,ammonium chloride, ammonium bromide, sodium nitrate, potassium nitrate,ammonium nitrate, ammonium sulfate, calcium nitrate, sodium carbonate,and potassium carbonate; any in combination with an aqueous-based fluid;and any combination thereof.

Suitable water-in-oil emulsions, also known as invert emulsions, mayhave an oil-to-water ratio from a lower limit of greater than about30:70, 40:60, 50:50, 55:45, 60:40, 65:35, 70:30, 75:25, or 80:20 to anupper limit of less than about 100:0, 95:5, 90:10, 85:15, 80:20, 75:25,70:30, or 65:35 by volume in the base fluid, where the amount may rangefrom any lower limit to any upper limit and encompass any subsettherebetween. Examples of suitable invert emulsions include thosedisclosed in U.S. Pat. No. 5,905,061 entitled “Invert Emulsion FluidsSuitable for Drilling” filed on May 23, 1997, U.S. Pat. No. 5,977,031entitled “Ester Based Invert Emulsion Drilling Fluids and Muds HavingNegative Alkalinity” filed on Aug. 8, 1998, U.S. Pat. No. 6,828,279entitled “Biodegradable Surfactant for Invert Emulsion Drilling Fluid”filed on Aug. 10, 2001, U.S. Pat. No. 7,534,745 entitled “Gelled InvertEmulsion Compositions Comprising Polyvalent Metal Salts of anOrganophosphonic Acid Ester or an Organophosphinic Acid and Methods ofUse and Manufacture” filed on May 5, 2004, U.S. Pat. No. 7,645,723entitled “Method of Drilling Using Invert Emulsion Drilling Fluids”filed on Aug. 15, 2007, and U.S. Pat. No. 7,696,131 entitled “DieselOil-Based Invert Emulsion Drilling Fluids and Methods of DrillingBoreholes” filed on Jul. 5, 2007, each of which are incorporated hereinby reference in their entirety. It should be noted that for water-in-oiland oil-in-water emulsions, any mixture of the above may be usedincluding the water being and/or comprising an aqueous-miscible fluid.

In some embodiments, the wellbore fluids described herein may be foamed.As used herein, the term “foam” refers to a two-phase composition havinga continuous liquid phase and a discontinuous gas phase. In someembodiments, the wellbore fluids may comprise a base fluid, theprecipitated particles described herein, a gas, and a foaming agent.

Examples of gases may include, but are not limited to, nitrogen, carbondioxide, air, methane, helium, argon, and any combination thereof. Oneskilled in the art, with the benefit of this disclosure, shouldunderstand the benefit of each gas. By way of nonlimiting example,carbon dioxide foams may have deeper well capability than nitrogen foamsbecause carbon dioxide emulsions have greater density than nitrogen gasfoams so that the surface pumping pressure required to reach acorresponding depth is lower with carbon dioxide than with nitrogen.Moreover, the higher density may impart greater particle transportcapability, up to about 12 lb of particles per gal of wellbore fluid.

In some embodiments, the quality of a wellbore fluid that is foamed mayrange from a lower limit of about 5%, 10%, 25%, 40%, 50%, 60%, or 70%gas volume to an upper limit of about 95%, 90%, 80%, 75%, 60%, or 50%gas volume, and wherein the quality may range from any lower limit toany upper limit and encompasses any subset therebetween. Mostpreferably, the wellbore fluid that is foamed may have a foam qualityfrom about 85% to about 95%, or about 90% to about 95%.

Examples of foaming agents may include, but are not limited to, cationicfoaming agents, anionic foaming agents, amphoteric foaming agents,nonionic foaming agents, or any combination thereof. Nonlimitingexamples of suitable foaming agents may, in some embodiments, include,but are not limited to, surfactants like betaines, sulfated orsulfonated alkoxylates, alkyl quarternary amines, alkoxylated linearalcohols, alkyl sulfonates, alkyl aryl sulfonates, C₁₀-C₂₀ alkyldiphenylether sulfonates, polyethylene glycols, ethers of alkylated phenol,sodium dodecylsulfate, alpha olefin sulfonates such as sodium dodecanesulfonate, trimethyl hexadecyl ammonium bromide, and the like, anyderivative thereof, or any combination thereof. Foaming agents may beincluded in foamed treatment fluids at concentrations ranging typicallyfrom about 0.05% to about 2% of the liquid component by weight (e.g.,from about 0.5 to about 20 gallons per 1000 gallons of liquid).

In some embodiments, the wellbore additives and/or the wellbore fluidsdescribed herein may optionally further comprise additional components,e.g., filler particles, salts, inert solids, fluid loss control agents,emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners,emulsion thickeners, viscosifying agents, gelling agents, crosslinkingagents, surfactants, cement particulates, proppants, gravelparticulates, lost circulation materials, pH control additives,breakers, defoaming agents, biocides, stabilizers, scale inhibitors, gashydrate inhibitors, oxidizers, reducers, friction reducers, claystabilizing agents, set accelerators, set retarders, and combinationsthereof. One skilled in the art with the benefit of this disclosureshould understand the appropriate composition, concentration, andcombination of individual additional components that may be included inthe wellbore additives and/or the wellbore fluids that comprise theprecipitated particles described herein.

The wellbore additives and/or the wellbore fluids described herein maybe used in a plurality of wellbore operations. Examples of wellboreoperations may, in some embodiments, include, but are not limited to,drilling operations, managed-pressure drilling operations, dual-gradientdrilling, tripping operations, logging operations, lost circulationoperations, stimulation operations, sand control operations, completionoperations, acidizing operations, scale inhibiting operations,water-blocking operations, clay stabilizer operations, fracturingoperations, gravel packing operations, wellbore strengtheningoperations, and sag control operations. The wellbore additives and/orthe wellbore fluids described herein may, in some embodiments, be usedin full-scale operations or pills. As used herein, a “pill” is a type ofrelatively small volume of specially prepared wellbore fluid placed orcirculated in the wellbore.

Some embodiments may involve circulating a wellbore fluid that comprisesa base fluid and precipitated particles described herein in a wellboresuch that the wellbore fluid has a desired density and optionally adesired level of sag control. In some instances, the wellbore fluid maybe a drilling fluid, a wellbore strengthening fluid, a cementing fluid,a fracturing fluid, a plugging fluid, completion fluids, and the likeand used in corresponding wellbore operations. In some instances, thewellbore fluid may further comprise other particles like anon-precipitated weighting agent particles, proppant particles, cementparticles, lost circulation particles, and the like, and any combinationthereof. In some instances, the precipitated particles may be a singletype or multiple types of precipitated particles.

In some embodiments, the precipitated particles described herein may beuseful in drilling operations. Some embodiments may involve drilling awellbore penetrating a subterranean formation with a wellbore fluid thatcomprises precipitated particles described herein. In some embodiments,the precipitated particles described herein may be useful in at leastone of: suspending wellbore cuttings (e.g., by contributing to the fluidviscosity and/or sag control), maintaining wellbore pressure (e.g., bycontributing to sag control), incorporating into filter cakes thatprovide fluid loss control, and the like. Further, precipitatedparticles described herein may be chosen to mitigate abrasion ofwellbore tools utilized during drilling.

In some embodiments, the precipitated particles described herein may beuseful in drilling operations. Some embodiments may involve drilling awellbore penetrating a subterranean formation with a wellbore fluid thatcomprises precipitated particles described herein. In some embodiments,the precipitated particles described herein may be useful in at leastone of: suspending wellbore cuttings (e.g., by contributing to the fluidviscosity and/or sag control), maintaining wellbore pressure (e.g., bycontributing to sag control), incorporating into filter cakes thatprovide fluid loss control, and the like. Further, precipitatedparticles described herein may be chosen to mitigate abrasion ofwellbore tools utilized during drilling.

In some embodiments, the precipitated particles described herein may beused in cementing operations. As used herein, the term “cementingoperations” refers to operations where a composition is placed in awellbore and/or a subterranean formation and sets therein to form ahardened mass, which encompasses hydraulic cements, constructioncements, linked precipitated particles described herein, and somepolymeric compositions that set (e.g., polymers like epoxies andlatexes).

Examples of cementing operations that may utilize the precipitatedparticles described herein may, in some embodiments, include, but arenot limited to, primary cementing operations (e.g., forming cementsheaths in a wellbore annulus or forming wellbore plugs for zonalisolation or fluid diversion) and remedial cementing operations (e.g.,squeeze operations, repairing and/or sealing microannuli and/or cracksin a hardened mass, or forming plugs). In cementing operations, aplurality of fluids are often utilized including, but not limited to,cementing fluids (sometimes referred to as settable compositions),spacer fluids, and displacement fluids. For example, a cementingoperation may utilize, in order, (1) a first spacer fluid, (2) acementing fluid, optionally (3) a second spacer fluid, and (4) adisplacement fluid, each of which may independently be a wellbore fluidcomprising precipitated particles described herein.

In some embodiments, cementing operations may utilize a plurality offluids in order such that each subsequent fluid has a higher densitythan the previous fluid. Achieving the desired density for a wellborefluid in a cementing operation may, in some embodiments, involve the useof precipitated particles described herein. Further, as describedherein, the precipitated particles utilized in such wellbore fluids maybe chosen to achieve other properties and/or capabilities in thewellbore fluids. It should be noted that in a cementing operation when aplurality of wellbore fluids are used, each wellbore fluid may beindependently designed with precipitated particles described herein anddo not necessarily require the use of the same precipitated particle ineach of the wellbore fluids or the use of a precipitated particledescribed herein in all of the wellbore fluids. For example, the firstspacer fluid may include fluorite, the cementing fluid may includeprecipitated manganese oxide, and the second spacer may includeprecipitated copper oxide.

One of ordinary skill in the art should understand the plurality of usesof the precipitated particles described herein and the appropriateincorporation into the wellbore fluids suitable for use in conjunctionwith cementing operations. For example, cementing fluids, spacer fluids,and/or displacement fluids, may comprise precipitated particlesdescribed herein so as to achieve a desired density, a desired level ofsag control, and/or a desired viscosity. In another example, linkableprecipitated particles may be included in the cementing fluids andutilized so as to yield hardened masses that comprise linkedprecipitated particles. In yet another example, degradable precipitatedparticles may be included in the cementing fluids and utilized so as toyield hardened masses that that can be at least partially degraded.Further, depending on the composition of the precipitated particle,combinations of the foregoing examples may be appropriate, e.g.,precipitated particles comprising manganese carbonate may be useful incementing fluids to achieve a desired density and a desired level of sagcontrol, to link in forming the hardened mass, and to degrade forincreasing the permeability of the hardened mass.

The exemplary precipitated particles and related fluids disclosed hereinmay directly or indirectly affect one or more components or pieces ofequipment associated with the preparation, delivery, recapture,recycling, reuse, and/or disposal of the disclosed precipitatedparticles and related fluids. For example, and with reference to FIG. 2,the disclosed precipitated particles and related fluids may directly orindirectly affect one or more components or pieces of equipmentassociated with an exemplary wellbore drilling assembly 200, accordingto one or more embodiments. It should be noted that while FIG. 2generally depicts a land-based drilling assembly, those skilled in theart will readily recognize that the principles described herein areequally applicable to subsea drilling operations that employ floating orsea-based platforms and rigs, without departing from the scope of thedisclosure.

As illustrated, the drilling assembly 200 may include a drillingplatform 202 that supports a derrick 204 having a traveling block 206for raising and lowering a drill string 208. The drill string 208 mayinclude, but is not limited to, drill pipe and coiled tubing, asgenerally known to those skilled in the art. A kelly 210 supports thedrill string 208 as it is lowered through a rotary table 212. A drillbit 214 is attached to the distal end of the drill string 208 and isdriven either by a downhole motor and/or via rotation of the drillstring 208 from the well surface. As the bit 214 rotates, it creates awellbore 216 that penetrates various subterranean formations 218.

A pump 220 (e.g., a mud pump) circulates drilling fluid 222 (e.g., adrilling fluid comprising the precipitated particles described herein)through a feed pipe 224 and to the kelly 210, which conveys the drillingfluid 222 downhole through the interior of the drill string 208 andthrough one or more orifices in the drill bit 214. The drilling fluid222 is then circulated back to the surface via an annulus 226 definedbetween the drill string 208 and the walls of the wellbore 216. At thesurface, the recirculated or spent drilling fluid 222 exits the annulus226 and may be conveyed to one or more fluid processing unit(s) 228 viaan interconnecting flow line 230. After passing through the fluidprocessing unit(s) 228, a “cleaned” drilling fluid 222 is deposited intoa nearby retention pit 232 (i.e., a mud pit). While illustrated as beingarranged at the outlet of the wellbore 216 via the annulus 226, thoseskilled in the art will readily appreciate that the fluid processingunit(s) 228 may be arranged at any other location in the drillingassembly 200 to facilitate its proper function, without departing fromthe scope of the disclosure.

One or more of the disclosed precipitated particles may be added to thedrilling fluid 222 via a mixing hopper 234 communicably coupled to orotherwise in fluid communication with the retention pit 232. The mixinghopper 234 may include, but is not limited to, mixers and related mixingequipment known to those skilled in the art. In other embodiments,however, the disclosed precipitated particles may be added to thedrilling fluid 222 at any other location in the drilling assembly 200.In at least one embodiment, for example, there could be more than oneretention pit 232, such as multiple retention pits 232 in series.Moreover, the retention put 232 may be representative of one or morefluid storage facilities and/or units where the disclosed precipitatedparticles may be stored, reconditioned, and/or regulated until added tothe drilling fluid 222.

As mentioned above, the disclosed precipitated particles and relatedfluids may directly or indirectly affect the components and equipment ofthe drilling assembly 200. For example, the disclosed precipitatedparticles and related fluids may directly or indirectly affect the fluidprocessing unit(s) 228 which may include, but is not limited to, one ormore of a shaker (e.g., shale shaker), a centrifuge, a hydrocyclone, aseparator (including magnetic and electrical separators), a desilter, adesander, a separator, a filter (e.g., diatomaceous earth filters), aheat exchanger, any fluid reclamation equipment. The fluid processingunit(s) 228 may further include one or more sensors, gauges, pumps,compressors, and the like used to store, monitor, regulate, and/orrecondition the exemplary precipitated particles and related fluids.

The disclosed precipitated particles and related fluids may directly orindirectly affect the pump 220, which representatively includes anyconduits, pipelines, trucks, tubulars, and/or pipes used to fluidicallyconvey the precipitated particles and related fluids downhole, withpumps, compressors, or motors (e.g., topside or downhole) used to drivethe precipitated particles and related fluids into motion, any valves orrelated joints used to regulate the pressure or flow rate of theprecipitated particles and related fluids, and any sensors (i.e.,pressure, temperature, flow rate, etc.), gauges, and/or combinationsthereof, and the like. The disclosed precipitated particles and relatedfluids may also directly or indirectly affect the mixing hopper 234 andthe retention pit 232 and their assorted variations.

The disclosed precipitated particles and related fluids may alsodirectly or indirectly affect the various downhole equipment and toolsthat may come into contact with the precipitated particles and relatedfluids such as, but not limited to, the drill string 208, any floats,drill collars, mud motors, downhole motors and/or pumps associated withthe drill string 208, and any MWD/LWD tools and related telemetryequipment, sensors or distributed sensors associated with the drillstring 208. The disclosed precipitated particles and related fluids mayalso directly or indirectly affect any downhole heat exchangers, valvesand corresponding actuation devices, tool seals, packers and otherwellbore isolation devices or components, and the like associated withthe wellbore 216. The disclosed precipitated particles and relatedfluids may also directly or indirectly affect the drill bit 214, whichmay include, but is not limited to, roller cone bits, PDC bits, naturaldiamond bits, any hole openers, reamers, coring bits, etc.

While not specifically illustrated herein, the disclosed precipitatedparticles and related fluids may also directly or indirectly affect anytransport or delivery equipment used to convey the precipitatedparticles and related fluids to the drilling assembly 200 such as, forexample, any transport vessels, conduits, pipelines, trucks, tubulars,and/or pipes used to fluidically move the precipitated particles andrelated fluids from one location to another, any pumps, compressors, ormotors used to drive the precipitated particles and related fluids intomotion, any valves or related joints used to regulate the pressure orflow rate of the precipitated particles and related fluids, and anysensors (i.e., pressure and temperature), gauges, and/or combinationsthereof, and the like.

While not specifically illustrated herein, one of ordinary skill in theart should recognize the modifications to drilling assembly 200 to allowfor performing other operations described herein including, but notlimited to, cementing operations, fracturing operations, and fluid flowcontrol operations.

In some embodiments, a wellbore drilling assembly may comprise a pump influid communication with a wellbore via a feed pipe; and a wellborefluid described herein disposed in at least one selected from the groupconsisting of the pump, the feed pipe, the wellbore, and any combinationthereof.

In some embodiments, a wellbore drilling assembly may comprise a pump influid communication with a wellbore via a feed pipe; a drill string withdrill bit attached to the distal end of the drill string; and a wellborefluid described herein in contact with the drill bit.

In some embodiments, a wellbore drilling assembly may comprise a pumpcapable of introducing a fluid into a wellbore via a feed pipe; a fluidprocessing unit capable of receiving the fluid from a wellbore via aninterconnecting flow line; and a wellbore fluid described hereindisposed in at least one selected from the group consisting of the pump,the feed pipe, the wellbore, the interconnecting flow line, the fluidprocessing unit, and any combination thereof.

In some embodiments, a wellbore drilling assembly may comprise a pumpcapable of introducing a fluid into a wellbore via a feed pipe; a mixinghopper upstream of the pump; and a wellbore fluid described hereindisposed in at least one selected from the group consisting of the pump,the feed pipe, the wellbore, and any combination thereof. The mixinghopper may be useful, in some embodiments, for implementing on-the-flychanges to the wellbore fluids described herein.

In the foregoing wellbore drilling assembly embodiments suitablewellbore fluids described herein may include, but are not limited to,

(a) a wellbore fluid having a density of about 7 ppg to about 50 ppg(including any subset described herein) and comprising a base fluid anda plurality of precipitated particles having a shape selected from thegroup consisting of ovular, substantially ovular, discus, platelet,flake, toroidal, dendritic, acicular, spiked with a substantiallyspherical or ovular shape, spiked with a discus or platelet shape,rod-like, fibrous, polygonal, faceted, star-shaped, and any hybridthereof;

(b) the wellbore fluid of (a), wherein the wellbore fluid has a sagcontrol of a density change of less than about 1 ppg over a time ofabout 10 hours to about 120 hours;

(c) the wellbore fluid of (a), wherein the precipitated particles have aspecific gravity of about 2.6 to about 20;

(d) the wellbore fluid of (a), wherein the precipitated particles have aspecific gravity of about 5.5 to about 20;

(e) the wellbore fluid of (a), wherein the precipitated particles have amedian diameter of about 5 nm to about 100 microns;

(f) the wellbore fluid of (a), wherein the wellbore fluid furthercomprises a plurality of second particles, the second particles beingprecipitated or non-precipitated;

(g) the wellbore fluid of (f), wherein the precipitated particles incombination with the second particles have a multiparticle specificgravity of about 3 to about 20;

(h) the wellbore fluid of (f), wherein the precipitated particles incombination with the second particles have a diameter distribution thathas at least one mode with a standard deviation of about 2% or less of apeak diameter of the mode; and

(i) the wellbore fluid of (f), wherein the precipitated particles incombination with the second particles have a multi-modal diameterdistribution.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered,combined, or modified and all such variations are considered within thescope and spirit of the present invention. The invention illustrativelydisclosed herein suitably may be practiced in the absence of any elementthat is not specifically disclosed herein and/or any optional elementdisclosed herein. While compositions and methods are described in termsof “comprising,” “containing,” or “including” various components orsteps, the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. All numbers and rangesdisclosed above may vary by some amount. Whenever a numerical range witha lower limit and an upper limit is disclosed, any number and anyincluded range falling within the range is specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Also, the terms in the claims have their plain, ordinary meaningunless otherwise explicitly and clearly defined by the patentee.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces. If there is any conflict in the usages of a word or term inthis specification and one or more patent or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

The invention claimed is:
 1. A wellbore drilling assembly comprising: apump in fluid communication with a wellbore via a feed pipe; and awellbore fluid disposed in at least one selected from the groupconsisting of the pump, the feed pipe, the wellbore, and any combinationthereof, wherein the wellbore fluid has a density of about 7 ppg toabout 50 ppg and comprises a base fluid and a plurality of precipitatedparticles having a shape selected from the group consisting of ovular,substantially ovular, discus, platelet, flake, toroidal, dendritic,acicular, spiked with a substantially spherical or ovular shape, spikedwith a discus or platelet shape, rod-like, fibrous, polygonal, faceted,star-shaped, and any hybrid thereof.
 2. The wellbore drilling assemblyof claim 1, wherein the wellbore fluid has a sag control of a densitychange of less than about 1 ppg over a time of about 10 hours to about120 hours.
 3. The wellbore drilling assembly of claim 1, wherein theprecipitated particles have a specific gravity of about 2.6 to about 20.4. The wellbore drilling assembly of claim 1, wherein the precipitatedparticles have a specific gravity of about 5.5 to about
 20. 5. Thewellbore drilling assembly of claim 1, wherein the precipitatedparticles have a median diameter of about 5 nm to about 100 microns. 6.The wellbore drilling assembly of claim 1, wherein the wellbore fluidfurther comprises a plurality of second particles, the second particlesbeing non-precipitated.
 7. The wellbore drilling assembly of claim 6,wherein the precipitated particles in combination with the secondparticles have a multiparticle specific gravity of about 3 to about 20.8. The wellbore drilling assembly of claim 6, wherein the precipitatedparticles in combination with the second particles have a diameterdistribution that has at least one mode with a standard deviation ofabout 2% or less of a peak diameter of the mode.
 9. The wellboredrilling assembly of claim 6, wherein the precipitated particles incombination with the second particles have a multi-modal diameterdistribution.
 10. A wellbore drilling assembly comprising: a pump influid communication with a wellbore via a feed pipe; a drill string withdrill bit attached to the distal end of the drill string; and a wellborefluid in contact with the drill bit, wherein the wellbore fluid has adensity of about 7 ppg to about 50 ppg and comprises a base fluid and aplurality of precipitated particles having a shape selected from thegroup consisting of ovular, substantially ovular, discus, platelet,flake, toroidal, dendritic, acicular, spiked with a substantiallyspherical or ovular shape, spiked with a discus or platelet shape,rod-like, fibrous, polygonal, faceted, star-shaped, and any hybridthereof.
 11. The wellbore drilling assembly of claim 10, wherein thewellbore fluid has a sag control of a density change of less than about1 ppg over a time of about 10 hours to about 120 hours.
 12. The wellboredrilling assembly of claim 10, wherein the precipitated particles have aspecific gravity of about 2.6 to about
 20. 13. The wellbore drillingassembly of claim 10, wherein the precipitated particles have a specificgravity of about 5.5 to about
 20. 14. The wellbore drilling assembly ofclaim 10, wherein the precipitated particles have a median diameter ofabout 5 nm to about 100 microns.
 15. The wellbore drilling assembly ofclaim 10, wherein the wellbore fluid further comprises a plurality ofsecond particles, the second particles being precipitated ornon-precipitated.
 16. A wellbore drilling assembly comprising: a pumpcapable of introducing a fluid into a wellbore via a feed pipe; a fluidprocessing unit capable of receiving the fluid from a wellbore via aninterconnecting flow line; and a wellbore fluid disposed in at least oneselected from the group consisting of the pump, the feed pipe, thewellbore, the interconnecting flow line, the fluid processing unit, andany combination thereof, wherein the wellbore fluid has a density ofabout 7 ppg to about 50 ppg and comprises a base fluid and a pluralityof precipitated particles having a shape selected from the groupconsisting of ovular, substantially ovular, discus, platelet, flake,toroidal, dendritic, acicular, spiked with a substantially spherical orovular shape, spiked with a discus or platelet shape, rod-like, fibrous,polygonal, faceted, star-shaped, and any hybrid thereof.
 17. Thewellbore drilling assembly of claim 16, wherein the wellbore fluid has asag control of a density change of less than about 1 ppg over a time ofabout 10 hours to about 120 hours.
 18. The wellbore drilling assembly ofclaim 16, wherein the precipitated particles have a specific gravity ofabout 2.6 to about
 20. 19. The wellbore drilling assembly of claim 16,wherein the precipitated particles have a specific gravity of about 5.5to about
 20. 20. The wellbore drilling assembly of claim 16, wherein theprecipitated particles have a median diameter of about 5 nm to about 100microns.